On May 1, 2018, ISO-NE filed a petition for waiver (“Petition”) of certain Tariff provisions to allow ISO-NE to retain two retiring generating units during the winter of 2023 and 2024 to maintain fuel security. According to ISO-NE, the potential retirement of these two generating units would both endanger 1,700 MW of winter generating capacity and also threaten the continued operations of the generators’ natural gas supplier, thereby increasing the risk of reserve depletion and load shedding in the ISO-NE region. On July 2, 2018, FERC rejected ISO-NE’s Petition, upon finding that the Petition sought to create a new process to address fuel security concerns outside of ISO-NE’s current Tariff (“July 2 Order”). FERC directed ISO-NE to propose short- and long-term Tariff revisions to remedy the fuel security issues identified in the record, or to show cause why none were necessary.

In compliance with the July 2 Order, ISO-NE submitted short-term Tariff revisions on August 31, 2018. ISO-NE proposal sought to retain certain resources for fuel-security purposes by: (1) implementing a Fuel Security Study Process for determining, based on specific criteria, whether a resource is needed to maintain fuel security; (2) using short-term cost-of-service agreements for such resources; (3) allocating the costs for the retained resources using a methodology consistent with ISO-NE’s previously-approved Winter Reliability Program; and (4) treating such resources as “price-takers” in ISO-NE’s Forward Capacity Market (“FCM”). ISO-NE requested an effective date of October 30, 2018 and explained that its proposed Tariff revisions would be temporary since ISO-NE will submit a long-term market solution to FERC for approval by July 1, 2019, as required by the July 2 Order.

In its December 3, 2018 Order, FERC accepted ISO-NE’s Tariff revisions to become effective October 30, 2018, as requested. FERC first concluded that the Fuel Security Study process was just and reasonable and directed ISO-NE to submit annual informational filings regarding the applicability of ISO-NE’s chosen study triggers, assumptions, and scenarios starting in the winter of 2018/19. Second, FERC agreed that ISO-NE’s cost allocation proposal was similar to the previously-approved Winter Reliability Program (an interim program designed to address reliability concerns during the winter), and therefore was a just and reasonable cost allocation method. Third, FERC accepted ISO-NE’s proposal to enter retained fuel security resources as price-takers in the FCM. FERC found that, absent such an approach, identified fuel security resources might not clear the Forward Capacity Auction (“FCA”) and consumers would have to “pay twice” for the capacity. As such, FERC found that ISO-NE’s proposal was consistent with previous precedent and would result in efficient and reasonable FCA outcomes. Finally, FERC accepted ISO-NE’s proposal to implement the Fuel Security Study process on an interim basis — specifically, for the FCAs associated with the capacity commitment periods of 2022/23, 2023/24, and 2024/25.

Chairman Chatterjee dissented from FERC’s ruling, arguing that two elements of the proposed Tariff revisions were unjust and unreasonable. First, Chairman Chatterjee asserted that treating fuel-secure resources as price-takers would be unjust and unreasonable under the Federal Power Act because such treatment would likely result in additional out-of-market interventions for these retiring resources, further suppressing prices, increasing retirements, and threatening fuel security in the ISO-NE region. Second, Chairman Chatterjee also stated that the sunset provision proposed by ISO-NE should be rejected as unjust and unreasonable because it could allow the ISO-NE Tariff to revert to a state without fuel security provisions, which he argued would be an unjust and unreasonable outcome based on the majority’s own conclusions.

]]>FERC Largely Rejects Complaint Alleging PJM Improperly Adjusted Market Prices After Transmission Outageshttps://www.troutmansandersenergyreport.com/2018/12/ferc-largely-rejects-complaint-alleging-pjm-improperly-adjusted-market-prices-transmission-outages/
Wed, 12 Dec 2018 21:23:12 +0000https://www.troutmansandersenergyreport.com/?p=10415On December 3, 2018, FERC largely rejected a complaint filed by Monterey MA, LLC (“Monterey”) alleging that PJM Interconnection, L.L.C. (“PJM”) improperly adjusted prices after two transmission line outage events for unauthorized reasons, and without proper notice and documentation in violation of PJM’s Tariff. Monterey requested that FERC reinstate original prices and that changes be made to the Tariff relating to price revisions so that re-pricing events are more transparent for market participants. FERC mostly found that Monterey’s allegations were unreasonable and thus largely denied Monterey’s complaint, including Monterrey’s request to reinstate the original market prices.

As a financial market participant that engages in virtual transactions in PJM, Monterey took financial positions in the day-ahead energy market based on its expectation of what real-time prices would be and subsequently lost money after PJM revised the market prices. Monterey alleged that its losses stemmed from PJM’s improper revision of the real-time prices following two separate transmission outages. Regarding the first event, Monterey advanced two arguments: (1) that PJM violated its Tariff by failing to include supporting documentation when it provided notice of the real-time final verified price revisions, and (2) that PJM’s decision to revise the final verified prices was based on incorrect data and that the revised prices should be re-settled using the correct information. FERC agreed with Monterey that PJM failed to provide the required documentation because PJM did not provide sufficient data or documentation to evidence its reason for the price correction so as to fully inform market participants. FERC declined, however, to grant Monterey’s requested relief to reinstate the original final verified prices because FERC found that the evidence in the record supported the conclusion that the price correction was warranted and, thus, ordering the reinstatement of an incorrect price would cause an “absurd” result and hinder confidence in the PJM energy market.

Regarding the second outage, Monterey argued that PJM acted without authority when it adjusted initially posted real-time prices. FERC found that PJM acted within its Tariff to adjust the initially posted prices. Specifically, FERC found that PJM’s Tariff describes in detail the process for calculating prices and that it would be unreasonable to conclude that PJM does not have the authority to ensure that such prices are correct and free of known errors prior to official posting on its website. FERC further pointed out that Monterey itself acknowledged elsewhere in its complaint that the initially posted prices on PJM’s website are subject to change. Thus, FERC denied Monterey’s complaint on this ground. FERC also denied Monterey’s request to require that PJM’s Tariff and Manuals’ processes for price revisions be revised, as well as to find that PJM’s denial of Monterey’s request for arbitration regarding the two pricing events be found to have violated PJM’s Tariff.

]]>FERC Declines to Require New CAISO Capacity Markethttps://www.troutmansandersenergyreport.com/2018/12/ferc-declines-require-new-caiso-capacity-market/
Tue, 04 Dec 2018 22:11:52 +0000https://www.troutmansandersenergyreport.com/?p=10413On November 19, 2018, FERC denied a complaint filed by CXA La Paloma, LLC (“La Paloma”) requesting that FERC use its jurisdiction over resource adequacy to direct the California Independent System Operator Corp. (“CAISO”) to implement centralized capacity procurement. FERC found that La Paloma failed to meet its burden to demonstrate that CAISO’s tariff was unjust, unreasonable, or unduly discriminatory or preferential under section 206 of the Federal Power Act.

In its complaint, La Paloma argued that California’s current resource adequacy regime increasingly requires participants to provide capacity from existing (often non-renewable) resources, such as the La Paloma gas-fired generating facility, and receive capacity payments that are four to seven times lower than those received by new (renewable) resources, resulting in a revenue shortfall. La Paloma argued that CAISO’s capacity market effectively functions based on a vertical demand curve, which it claimed leads to highly volatile capacity payments and may lead to other market inefficiencies. Previously, in 2016, CAISO denied a request to approve an economic outage for the underlying generating facility, a decision that was later upheld by FERC. According to the La Paloma complaint, such decisions, coupled with the very low capacity payments for existing resources, demonstrate market failures in CAISO that could eventually lead to reliability issues in California.

In response, CAISO argued that granting the complaint would threaten to undo CAISO’s existing bilateral procurement framework for capacity and force changes more in line with the eastern RTO/ISOs. As noted in FERC’s order, PJM Interconnection, L.L.C., New York Independent System Operator, Inc., and ISO New England Inc. have all recently transitioned from a vertical demand curve to a sloped demand curve for capacity.

Ultimately, FERC rejected La Paloma’s arguments for multiple reasons. FERC reiterated that suppliers in a competitive wholesale market are not guaranteed full cost recovery, but simply the opportunity to recover their costs. FERC also noted that La Paloma’s complaint focused mainly on low capacity prices that were attributed to California’s capacity surplus and that low prices do not in and of themselves demonstrate market failure. Similarly, FERC reasoned that an increase in CAISO actions regarding economic outages that require generators to offer capacity did not demonstrate any reliability concerns. With regard to other regional transmission organizations and independent system operators, FERC noted that it has consistently rejected a one-size-fits-all approach to resource adequacy because each region has significant differences that must be accounted for and there can be more than one just and reasonable rate. Instead, FERC expressed confidence that upcoming CAISO and California Public Utilities Commission proceedings would appropriately address the changing grid conditions in California.

To ensure resource adequacy, ISO-NE holds a forward capacity auction (“FCA”) annually, three years in advance of the relevant capacity delivery year (the Capacity Commitment Period). Resources compete in the FCA to obtain a commitment to supply capacity (a CSO) in exchange for a market-priced capacity payment. Under the ISO-NE Tariff, a resource that is planned or under construction, i.e., not yet commercially operational, may qualify to offer capacity into an FCA if certain criteria are met. If a resource with a CSO has not achieved commercial operation by the start of the Capacity Commitment Period, it must cover its obligation for the period in which the resource will not be operational, either by purchasing replacement capacity or by entering into one or more CSO bilateral transactions.

ISO-NE may seek to terminate a resource’s CSO if one or more of several conditions are satisfied, two of which are applicable in this case: (1) if a resource covers a CSO for two Capacity Commitment Periods, or (2) if the date by which a resource will have achieved commercial operation is more than two years after the beginning of the Capacity Commitment Period for which the resource first received a CSO. In its filing, ISO-NE argued that both of those conditions under its Tariff had been met because (1) Invenergy had covered Clear River’s CSO for the 2019–2020 and 2020–2021 Capacity Commitment Periods and (2) Clear River will not achieve commercial operation until two years beyond the 2019–2020 period.

In its order, FERC found that ISO-NE had the right to seek termination of Clear River’s CSO for 2021–2022 under its Tariff because Invenergy did not dispute that it covered Clear River’s CSO for the 2019–2020 and 2020–2021 Capacity Commitment Periods. Because FERC found this first condition for termination had been met, it did not opine on the issue of whether Clear River will achieve commercial operation more than two years after the beginning of the 2019–2020 Capacity Commitment Period. Accordingly, FERC accepted ISO-NE’s request to terminate Clear River’s CSO for the 2021–2022 Capacity Commitment Period as just and reasonable.

In addition to protesting ISO-NE’s termination filing, Invenergy also requested waiver of any requirement in the ISO-NE Tariff that would require immediate forfeiture of Clear River’s financial assurance or prohibit Clear River from participating in FCA 13, to be held in February 2019. FERC, however, denied Invenergy’s waiver request because it found that the waiver would result in undesirable consequences for both system planning, because it could skew the results of interconnection studies and transmission planning studies, and FCA market pricing, because it risks misrepresenting capacity availability for the associated delivery years.

In June 2016, FERC first accepted proposed tariff revisions from CAISO in response to a large natural gas leak that occurred at Aliso Canyon in October 2015 (see December 6, 2017 edition of the WER). The tariff revisions established market measures, on an interim basis, to address the reliability and system operational risks presented by the Aliso Canyon event. In November 2016, FERC accepted CAISO’s proposal to extend the provisions for an additional year. In November 2017, while FERC once again accepted CAISO’s proposal to extend the same provisions for another year, it denied CAISO’s proposal to make certain provisions permanent. However, FERC did clarify in that same order in 2017 that rejection of the permanent tariff provisions would not foreclose CAISO from proposing to extend the tariff provisions for an additional year.

In its order, FERC accepted in part and rejected in part CAISO’s proposed tariff revisions. With one exception, FERC temporarily extended all of the the tariff provisions as proposed, each of which are now set to expire on December 31, 2019. FERC extended these provisions after concluding that these provisions remain a just and reasonable approach to continuing to ensure that CAISO has the measures and tools it needs to address risks associated with the limited operability of Aliso Canyon. However, FERC rejected CAISO’s request to extend the tariff revisions related to the gas price scalars. According to a report by the CAISO Department of Market Monitoring, CAISO’s use of the gas price scalars over the past year were not only ineffective, but also affected the market by weakening market power mitigation, increasing bid cost recovery, and imposing costs on consumers. FERC found this report persuasive and concluded that the proposed extension would not be just and reasonable.

During his confirmation hearing held on November 15, 2018, a significant focus was whether Mr. McNamee could be impartial at FERC, given that he took on an active role in the Department of Energy’s (“DOE”) proposed rulemaking regarding grid resilience. While testifying, Mr. McNamee expressed his commitment to be impartial and resource-neutral, despite his role in the DOE rulemaking process on resilience (see November 20, 2018 edition of the WER).

In addition to Mr. McNamee’s nomination, the ENR Committee also approved other energy-related nominees on Tuesday. Dr. Rita Baranwall and Mr. David Vela, nominated to be Assistant Secretary for Nuclear Energy at DOE and Director of the National Park Service respectively, received unanimous approval by voice vote. With their approval by the ENR Committee, the nominees will now go before the full Senate for a confirmation vote. A copy of the ENR Committee’s press release regarding the nominees’ advancement to the full Senate is available here.

As FERC explained in the NOPR, ADIT arises from timing differences between Internal Revenue Service reporting and how income taxes are recovered in rates. As corporate tax liabilities decrease, so do a utility’s ADIT liabilities and assets, which can have ratemaking consequences. With regards to the NOPR, FERC’s proposal would require transmission providers to revise their rates to account for the tax law’s effects. FERC’s proposed reforms would: (1) adjust a utility’s rate base to reflect changes in deferred income taxes; (2) include mechanisms that would raise or lower income tax allowances; and (3) incorporate a new worksheet into rates that tracks annual ADIT information.

In addition, FERC issued the Policy Statement explaining which accounts companies should record the amortization of excess and deficient ADIT in and how to address any such excess or deficiency as a result of assets being sold or retrieved—namely that excess and deficient ADIT amounts must continue to be recorded after an asset sale or retirement.

In separately issued orders, FERC also approved revised line items for income tax in certain public utilities’ formula rates and revised income tax rates in certain utilities’ stated rates to reflect the federal tax rate reduction and provided blanket approval for the reclassification of certain stranded tax effects resulting from the TCJA.

Washington’s attempt at being the first state to implement a carbon tax (“Initiative 1631”) was rejected by voters. The initiative would have set a carbon price of $15/metric ton on fossil-fuel emissions. 56.3 percent of voters opposed Initiative 1631, while 43.7 percent voted in favor of the initiative. Similarly, Colorado’s attempt to limit oil and gas drilling (“Proposition 112”) was also rejected by voters. Proposition 112 would have required oil and gas drilling to be further distanced from homes, businesses and waterways; Colorado voters rejected the proposition by a 57 percent-to-43 percent vote. In Arizona, voters rejected a renewable energy mandate (“Proposition 127”), providing a decisive win (70-30) to the state’s existing power system. Proposition 127 would have required Arizona utilities to source 50 percent of its power from renewable energy resources by 2030.

Because certain Nevada state initiatives require a second approval by voters, two important ballots were at play this year. First, in 2016, Nevada voters initially approved a retail choice bill (“Question 3”). Although Question 3 passed nearly two to one in 2016, its follow up vote was rejected by voters last Tuesday. Second, Nevada voters passed initial approval for a 50 percent renewable energy mandate (“Question 6”). Voters will need to pass Question 6 again in 2020 in order for the initiative to take effect.

]]>Wind Developers File Complaint Against SPP Exit Fee for IPPs, non-TOs, and non-LSEshttps://www.troutmansandersenergyreport.com/2018/11/wind-developers-file-complaint-spp-exit-fee-ipps-non-tos-non-lses/
Mon, 12 Nov 2018 15:18:55 +0000https://www.troutmansandersenergyreport.com/?p=10373On November 5, 2018, the American Wind Energy Association and the Wind Coalition (together, the “Wind Developers”) filed a complaint against Southwest Power Pool, Inc. (“SPP”) regarding SPP’s Bylaws and Membership Agreement. Specifically, the Wind Developers object to the sections of the Bylaws and Membership Agreement which impose financial obligations (“exit fees”) on independent power producers (“IPPs”), other comparable non-transmission owners (“non-TOs”), and non-load-serving entities (“non-LSEs”). The Wind Developers argue that the exit fee violates cost causation principles, may pose a barrier to entry into SPP to vote on critical issues, directly affects jurisdictional rates, and that therefore, the exit fee is unjust, unreasonable, and unduly discriminatory.

SPP’s Bylaws and Membership Agreement provide for members to forfeit an exit fee if they seek to withdraw from membership in SPP. Section 8.7 of SPP’s Bylaws states that withdrawing members must pay for SPP’s immediate or long-term costs, including “debts under all mortgages [and] loans,” “all payment obligations under…leases,” and “employee pension funds.” Section 4.2.1 of SPP’s Membership Agreement obligates withdrawing members to submit a withdrawal deposit of at most $150,000, and provides that SPP “will not accept a notice of intent to withdraw without a withdrawal deposit.” The Membership Agreement also makes clear that SPP will not accept the deposit as being a full fulfillment of SPP’s costs to formally withdraw a member from the organization. Although the exact fee is not known prior to withdrawal, the fee could range from $700,000 to $1 million.

In the complaint, the Wind Developers argue that the exit fee violates FERC’s fundamental cost causation principle. Under the cost causation principle, FERC must ensure that a company recovers its costs from the entities that cause the company to incur those costs. The Wind Developers argue that the exit fee is used to underwrite a situation where a future member would seek to join SPP and would be used to satisfy future costs from which the withdrawing member would not benefit. The Wind Developers contend that the exit fee is for costs that “are unrelated to the exiting member,” and members should not be responsible to “carry the risk and liability for costs that they are not responsible for causing in the SPP market.”

The Wind Developers also claim that the exit fee could directly affect jurisdictional rates because it erects barriers to entry into SPP. The Wind Developers state that the ratio of IPPs/non-TOs/non-LSEs to full TOs and LSEs is extremely low as compared to other organizations, which leads SPP to be less reflective of the full interests of all market participants. The Wind Developers maintain that because there are more TOs and LSEs within SPP, the TOs and LSEs can dominate when SPP’s policies come up for a vote. The Wind Developers further argue that IPPs, non-TOs, and non-LSEs currently do not have a “reasonable opportunity to develop, vote on, and determinate SPP’s…rates, terms, and conditions of service.” The Wind Developers therefore argue that this problem impinges on SPP’s decision-making process to produce rates that are just and reasonable.

The Wind Developers request FERC to find that the membership exit fees, as applied to IPPs, non-TOs, and non-LSEs, are unjust and unreasonable, and to require SPP to adopt revisions to Sections 8.7 of its Bylaws and 4.2.1 of its Membership Agreement. Answers to and comments on the complaint are due by 5pm on November 26, 2018.

]]>FERC Accepts Revisions to the Locational Aspects of MISO’s Resource Adequacy Constructhttps://www.troutmansandersenergyreport.com/2018/11/ferc-accepts-revisions-locational-aspects-misos-resource-adequacy-construct/
Wed, 07 Nov 2018 16:42:55 +0000https://www.troutmansandersenergyreport.com/?p=10368On October 31, 2018, FERC accepted revisions to the Midcontinent Independent System Operator, Inc.’s (“MISO”) Open Access Transmission, Energy and Operating Reserve Markets Tariff (“Tariff”) to enhance the locational aspects of its resource adequacy construct (“Filing”). In March of 2018 (“March 2018 Filing”), MISO had proposed a similar filing, which FERC rejected, without prejudice, on August 2, 2018. There, FERC found two elements of the March 2018 Filing to be unjust and unreasonable, but FERC provided MISO with guidance with respect to any future filing. With the exception of those two elements, MISO stated that its Filing contains the same proposal and justification for the proposal as in its March 2018 Filing.

Regarding (1), the treatment of External Resources, MISO identified reliability and inequity concerns associated with the way it currently models External Resources. As a solution, MISO proposed to model and price External Resources in newly created External Resource Zones that will still count towards satisfying MISO’s region-wide Reserve Requirement but will not count towards satisfying the Local Clearing Requirement for any MISO Local Zone. MISO stated that its proposal appropriately reflects the location of External Resources and enables states and load serving entities (“LSEs”) within those states to have an accurate accounting of their local resource needs and their capabilities to utilize resources from outside their Local Zone. FERC found it just and reasonable for MISO to no longer count all External Resources towards satisfying the Local Clearing Requirements for MISO’s Local Zones because, according to FERC, continuing to do so would undermine the purpose of the Local Clearing Requirement, which is to ensure that a sufficient amount of capacity is located within each Local Zone so that each Local Zone can meet its Loss of Load Expectation (“LOLE”) during its Local Zone Peak Demand when it is import constrained. FERC disagreed with protestors regarding allegations of undue discrimination and found that MISO reasonably demonstrated that Border External Resources (a resource that has a point of interconnection at a substation that contains the terminal of a transmission line under MISO’s functional control) warrant different treatment than their External Resources for the limited purpose of satisfying Local Clearing Requirements.

Regarding (2), Historical Unit Considerations, MISO proposed that, because of the changes to its treatment of External Resources, it is necessary and equitable to introduce HUCs, a new methodology to allocate excess auction revenue. MISO explained that, under its HUCs proposal, if capacity prices in the auction separate, MISO will allocate the resulting excess auction revenue to LSEs with historic arrangements, such as Grandfathered Agreements, pre-zonal capacity contracts (i.e., arrangements that predate July 20, 2011), or pre-March 26, 2018 (i.e., the date of the March 2018 Filing) contracts with External Resources. FERC explained that, because under the MISO HUCs proposal the amount of existing arrangements that are eligible for HUCs will decrease over time and eventually no HUCs will remain, FERC found that the HUCs proposal is a just and reasonable solution that will not embed inefficiencies in MISO’s resource adequacy construct.

Finally, with respect to (3), Market Parameters, MISO proposed to further align its locational market parameters, such as Capacity Import Limits, Capacity Export Limits, and Local Clearing Requirements, with auction assumptions and visibility by requiring the output from all resources in its LOLE studies to be aligned with the Local Zone or External Zone in which they are accredited in the auction. FERC found MISO’s alignment proposal to be just and reasonable.